A conventional geologic model, as used in the oil and gas industry, or for subsurface imaging in general, is a computer-based representation of a subsurface earth volume, such as a petroleum reservoir or a depositional basin. Technology for three-dimensional (3D) geological modeling or static reservoir modeling continues to advance.
Seismic-to-simulation using seismic data (“seismic”) is the process of generating three-dimensional models of a subsurface earth volume. Such models are used for imaging reservoirs for predicting storage, or for hydrocarbon production, selecting well placement, and optimizing reservoir management in general. A resulting three-dimensional model should faithfully represent original well logs, seismic data, and production history.
A “dip” as used in the seismic modeling arts, may be defined as an attribute that computes, for each seismic trace, the best fit plane (3D), or line (2D), between its immediate neighbor traces on a horizon, and outputs the magnitude of dip (gradient) of the plane or line, in degrees or other measure. The dip attributes can be used to create a pseudo-paleogeologic map on a horizon slice or other seismic map or image. A horizon is a subsurface interface, layer, or layer boundary, between two substances, e.g., between two layers of rock. Thus, a horizon is a 3D surface in the actual earth volume, but may be represented in 3D or in 2D, when imaged.
A fundamental problem with conventional dip estimation methods is their reliance on calculating only local estimates of dip, without taking into account global consistency constraints. The local dip estimations can be calculated through cross-correlation, or gradient-based methods. In order to make these local estimates look consistent and spatially continuous, conventional methods usually apply a mean filter to the local estimates for smoothing. But these conventional dip estimating techniques can be improved.